Regional Geology 5 Production History 14 METHODS 17 RESULTS 23 CONCLUSION/DISCUSSION 36 REFERENCES: 38 APPENDICES 41 Appendix a 41 Appendix B 48

Kelly Joe Harrington

2014

Carbon Capture and Sequestration and CO2 Enhanced Oil Recovery in the

Temblor Formation Sandstones at McKittrick oil field, San Joaquin Valley,

California

Kelly Joe Harrington B.S.

A Thesis Submitted to the Department of Geological Sciences

California State University, Bakersfield

In Partial Fulfillment for the Degree of Masters of Science In Geology

Fall 2014

Acknowledgements

I would like to express my deepest appreciation to Dr. Janice Gillespie, my committee chair. She has provided guidance and support for the progress of this research. She has demonstrated much patience and endurance through the revision process as she had to endure many drafts to perfect this work. Without her patience and expertise this thesis would not be. I can’t express the amount of encouragement she has provided to persuade me to quit work and focus on my thesis while providing scholarship opportunities. She was my first Geology professor and will always have a special place in my heart as she has shown me the love of geology.

Dr. Negrini provided encouragement and allowed me to be part of the CREST scholarship which provided income that I may concentrate on my education. He has also been an inspiration to complete this work in a timely manner.

I would also like to thank Preston Jordan for providing advice and expertise through the making of this work.

I would like to thank my committee chairs; Dr. Dayanand Saini and Brian Taylor which have provided much appreciated feedback in refining this thesis. Dr. Dayanand Saini spent countless hours consulting with me to provide a deeper understanding into the engineering aspects of Carbon Capture and Sequestration.

Thanks to Joshua Atkins, and Noe Torres who worked hard on obtaining the production data from the historical production records and digitizing the information into a workable excel spreadsheet.

Chevron USA has provided consultations to aide in understanding the study area and troubleshooting Petrel issues. They also provided much needed digital logs to assist in this research.

I would like to extend a special thank you to my family and God whom have provided the moral support and strength through the most trying times. Without their love and patience I would not have been able to continue this work to its completion.

Table of Contents

Table of Contents v List of Figures vii List of Tables viii List of Appendices viii ABSTRACT ix INTRODUCTION 1 Regional Geology 5 Production History 14 METHODS 17 RESULTS 23 CONCLUSION/DISCUSSION 36 REFERENCES: 38 APPENDICES 41 Appendix A 41 Appendix B 48

List of Figures

Figure 1: San Joaquin Basin map...... 6 Figure 2: Generalized stratigraphy column of the San Joaquin Valley ...... 8 Figure 3: Southern San Joaquin Basin generalized cross section...... 11 Figure 4: Phacoides Isopach map with log signatures ...... 13 Figure 5: Type log for well 562 ...... 14 Figure 6: Structure map on the top Phacoides ...... 16 Figure 7: Petrel 3d geological model ...... 24 Figure 8: West to east cross-section depicting compartmentalization ...... 25 Figure 9: Fault block diagram ...... 26 Figure 10: Production history by fluid stream graph ...... 29 Figure 11: Well by well production map with isopach ...... 30 Figure 12: Hydrostatic pressure graphs ...... 32 Figure 13: Spatial analysis of fractional hydrostatic pressure...... 34

List of Tables

Table 1: Production and CO2 space available by fault block ...... 28

vii

List of Appendices

Appendix A……………………………………………………………………………...………………………………….41 Appendix B……………………………………………………………………………...………………………………….48

viii

Abstract

Depleting oil and gas fields are ideal storage sites for atmospheric carbon dioxide because of their large capacities and proven ability to retain fluids for millions of years. In addition, the

CO2, when injected at depths greater than 3000 feet, can increase recovery of remaining oil in place by an additional 10% - 20% of the original oil in place (OOIP). This research investigates the possibility of carbon capture and sequestration (CCS) in the Phacoides member of the

Temblor Formation in the McKittrick oil field located in the San Joaquin Valley of California.

The Phacoides reservoir has produced 71.5 MMRB (million reservoir barrels) of fluid equivalent to approximately 5.8 million tons of CO2. Through CO2 EOR an additional 17 MMBO (million barrels of oil) may be recoverable, thereby offsetting the cost of CCS. Faulting has compartmentalized the reservoir into at least six separate fault blocks requiring at least five separate injection wells in order to fill each of the blocks. The presence of faulting also increases the risk of CO2 leakage. Pressure analysis also revealed the presence of a weak water drive which will fill some of the vacated pore space available for CO2 sequestration—especially along the flanks of the structure.

Introduction

Carbon Capture and Sequestration (CCS) is a promising new technology to help prevent the

release of greenhouse gases (GHG’s) into the atmosphere, ultimately delaying the effects of climate change (Sundquist et al., 2008). The global annual emissions of anthropogenic GHG have almost doubled from 1970 to 2004. Most production of GHGs are from energy and

industrial sources with CO2 gases making up over 50 percent of the GHGs released (IPCC, 2008).

According to atmospheric models developed by the U.S. Climate Change Science Program

(CCSP), in order to stabilize an atmospheric C02 level at 550 ppm, global emissions must be reduced by 75 percent over the next century (Sundquist et al., 2008).

CCS is the process of capturing carbon dioxide (CO2) at stationary sources that emit high volumes of GHG’s and injecting the gas into underground geologic reservoirs or the deep ocean for permanent storage (Kaldi et al., 2009). Depleted oil and gas reservoirs are ideal storage sites for CO2 because of their proven containment of buoyant fluids (Kaldi et al., 2009). They have been thoroughly studied, providing an abundance of publicly accessible surface and subsurface data and have existing infrastructure already in place that can be adapted for CCS implementation.

In 2007, a nationwide study was conducted by the USGS to determine ideal conditions for CCS

in depleted oil fields (Burruss et al., 2009). The following criteria were developed for geological

storage:

1. Formation water salinity of the reservoir cannot be less than 10,000 mg/L TDS.

Waters with salinity less than 10,000 mg/L TDS are considered a possible water

supply by the U.S. Environmental Protection Agency (EPA) and should be protected

from potential sources of contamination.

2. The depth of the reservoir must be 3000 feet or greater. At this depth, the pressure

and temperature are sufficient for CO2 to maintain a supercritical fluid state. At

these conditions, the density of CO2 is less than water and similar to oil. The CO2

fluid would migrate upward and become trapped in the same structural traps that

have retained oil deposits for millions of years.

3. Minimum production of reservoir must be 12.5 MMbbl oil --equivalent to 1-1.4

million metric tons of CO2 at reservoir conditions.

The largest constraint on implementing CCS projects is the cost of capturing, transporting and monitoring CO2 (IPPC, 2005). Depleted oil fields have the infrastructure in place to transport

and monitor CCS adequately. However, the current technology for CO2 capture is not

economically viable for mass production and installation. Current costs of CCS are estimated to be as much as $31/ton (Myers et al., 2006). This does not include the cost of retrofitting a

power plant to capture CO2 since the cost can vary greatly depending on the type and amount of emissions produced (Myers et al., 2008). The cost of CCS can be offset by turning the waste carbon dioxide into a commodity for CO2 EOR. Thus, storing CO2 in depleted oil reservoirs is a

good starting point for the ultimate goal of larger scale storage in higher volume saline aquifers

(IPCC, 2005).

In many mature oil fields, much of the remaining oil in place has not been recovered under

primary and secondary methods. The use of CO2 EOR has resulted in recovery rates as high as

10-20% of the original oil in place (OOIP) (Enick and Olsen, 2012). Most current CO2 EOR

projects in the US lie within the Permian basin of west Texas where natural sources of CO2 are

readily available (Advanced Resources International, 2006). It is estimated that over 57.3

million barrels of residual oil in California are stranded in mature reservoirs and 6.3 million may

be recoverable by CO2 EOR (The National Energy Laboratory, 2009).

A typical CO2 EOR process consists of injecting slugs of CO2 chased by water slugs to push the

comingled fluid toward production wells. In most reservoirs below 3000 feet, the CO2 forms a

supercritical fluid that becomes miscible with oil, swelling the oil and forming a homogeneous

mixture. The viscosity of the oil is lowered and its volume and pressure increases thereby

increasing its mobility in the reservoir. The produced comingled fluid is then separated and the

CO2 is removed to be reused in the next flood cycle. Eventually, upon termination of EOR, the

CO2 fluid replaces the produced oil and gas and becomes permanently sequestered in the

reservoir (The National Energy Laboratory, 2009).

A comprehensive study of several depleting oil fields in the San Joaquin Valley of California was conducted and three main reservoirs were identified as candidates for CCS in Kern County.

These reservoirs produce in a number of different fields but three of the largest fields were chosen for additional study: the Temblor Formation in the McKittrick oilfield, the Stevens

Sandstone in the North Coles Levee field, and the Vedder formation in the Greeley field

(Gillespie, 2011).

This research analyzes the potential for CCS in the Phacoides sandstone reservoir of the

Temblor Formation in the McKittrick oil field. The McKittrick field is located within two miles of

the La Palma power generation plant which would provide 4.5 million tons of CO2 per year if

retrofitted for carbon capture (WESTCARB, 2014). The study area is located in the northeast section of the field which encompasses 1450 proved acres with over 94 wells producing from 6

zones within the deeper sands of the field (Weddle, 1965). Estimation of total available CO2

storage volume is determined using subsurface maps to examine the degree of stratigraphic and structural compartmentalization of the sand bodies. Well-by-well production data were compiled to determine the net volume of reservoir fluids that have been produced since the discovery of the pool. By comparing reservoir pressure variations as production occurred we can identify compartments not visible through mapping techniques and predict the behavior of the reservoir during the process of CO2 injection. The goals for this project are to determine the overall extent and reservoir quality of the sandstones, estimate the amount of CO2 storage

space, determine the reservoir’s pressure response to fluid injection and removal and calculate

the possible amount of recoverable oil from CCS as a method for EOR.

Regional Geology

The San Joaquin Basin is one of the most productive areas in the world for oil and gas (Scheirer and Magoon, 2007). It is situated in the southern portion of the 700 km long Central Valley of

California (Bartow, 1991; Galloway and Riley, 1999). The San Joaquin valley is an asymmetric structural trough filled with upper Mesozoic and Cenozoic sediments up to 9 km thick (Bartow,

1991). The basin is surrounded by mountainous terrain and lies between the Sierra Nevada to the east, the Tehachapi/San Emigdio mountains to the south and the Temblor range to the west

(Fig 1) (Galloway and Riley, 1999). The northern boundary of the San Joaquin basin is the

Stockton Arch; a buried structural high that separates the San Joaquin basin from the

Sacramento basin to the north (Bent, 1988).

Figure 1. San Joaquin Basin map depicting location and limits of the basin in red. The area for this study is depicted by an orange box (modified from Gautier et al., 2003)

The San Joaquin basin originated in Mesozoic time as a forearc basin adjacent to an east dipping subduction zone (Bartow, 1991; Reid, 1995). The subduction of the Farallon plate

created an active magmatic arc complex under the Sierra Nevada region to the east of the San

Joaquin basin (Reid, 1995).

The Temblor formation was deposited in the basin during Oligocene to Middle Miocene time and consists of the Cymric Shale Member, Phacoides (Wygal) Member, Lower Santos shale

Member, Agua Sandstone Member, Upper Santos Shale Member, Carneros Sandstone

Member, the Media Shale Member and the Buttonbed Sandstone Member (Weddle, 1965). A stratigraphic column for the study area is shown in Figure 2.

Phacoides Ss Mbr

Figure 2. Generalized stratigraphic column depicting stratigraphic units in the eastern and western part of the southern San Joaquin valley (Gautier and Scheirer, 2008). The shaded area highlights the Temblor Formation. The study area lies in the western part of the valley.

Throughout the Oligocene, the area remained a convergent margin tectonic regime where plutoniclastic sandstones were widely deposited throughout the basin. In early Oligocene time, the Cymric Shale member was being deposited in a marine setting at middle bathyal depths of 4920-6560 feet (Carter, 1985). A major regression occurred by the middle Oligocene creating a shallow marine environment in which the Phacoides member was deposited. A subsequent transgression event in mid-Oligocene time caused a transition back to mid-bathyal depths in which the lower Santos shale member was deposited (Weddle, 1965; Carter, 1985).

By the late Oligocene another regression event occurred, possibly due to tectonic uplift, depositing the Agua sandstone member (Carter, 1985).

In early Miocene time, the subduction zone encountered the East Pacific rise. This terminated subduction and a shift in tectonic regime from a convergent plate margin to a transform margin occurred (Reid, 1995). The Mendocino triple junction and associated San Andreas Fault (SAF) system were formed as the Pacific plate moved north relative to the San Joaquin basin (Reid,

1995; Graham et al., 1989).

In early Miocene time, the basin experienced another transgression returning to a deep ocean middle bathyal environment where the upper Santos Shale member was deposited, reaching a thickness of 400 to 800 feet. By the end of the Saucesian stage of the Miocene, the Carneros

Sandstone member was deposited as turbidite sands in a middle bathyal environment (4920-

6560 feet depth) (Carter, 1985). Overlying the Carneros is the Media Shale member, consisting

of brown to gray shales and siltstones with an average thickness of 275 feet deposited in a middle bathyal environment (Carter, 1985).

A regression occurred in the Relizian stage of Miocene time causing a return to shallow marine depths. The Button Bed sandstone was deposited at this time. The Buttonbed Sandstone is absent to the west near the San Andreas fault suggesting that it was removed by erosion due to regional uplift (Pence, 1985). This sandstone is not present in the study area.

Throughout Miocene time, marine sediments were restricted to the southern part of the San

Joaquin Basin. These sediments were transported through a narrow seaway on the western margin of the basin limiting the deposition and extent of the Carneros and Buttonbed

Sandstone members (Bartow, 1991).

The west side of the basin has been very structurally deformed because of its geographic proximity to the SAF system (Bartow, 1991). In the late Miocene, the transform regime along the SAF changed to transpression creating pronounced en echelon folding near the SAF and lower amplitude folding toward the basin center (Bartow, 1991; Weddle, 1965). The fold belt created many structural traps for oil accumulations. A generalized cross section from west to east across the basin depicts the deformation of the Temblor formation along the west side of the basin (Fig 3).

Figure 3. A generalized cross section west to east across the San Joaquin Basin depicting the deformation of the Temblor formation along the west side of the basin (modified from CA DOGGR, 1998). The Temblor Formation is highlighted in yellow. The inset map depicts the cross section line across the Southern San Joaquin Valley (modified from Gautier et al., 2003).

In the study area, the Zemorrian Age Phacoides sandstone member unconformably overlies the

Cymric Shale member and is the lowest sandstone member in the type Temblor Formation

(Carter, 1985). This member has been referred to as both the Phacoides Reef by Kleinpell

(1938) and the Wygal by Dibble (1973) creating much confusion in its identification throughout the valley. The Phacoides comprises three lithofacies: a sporadically occurring basal sandstone, a highly fossiliferous sandy siltstone and an upper glauconitic and phosphatic

sandstone (Carter, 1985). The deposits and fossil assemblages suggest a shallow marine depositional environment (Carter, 1985). In the study area, the member is a light-gray to tan, sandy siltstone, grading into massive, friable sandstone (Weddle, 1965). The sediment source for the Temblor is believed to have been from the west in the uplifted Diablo Range (Graham et al., 1989). The Phacoides sandstone varies in thickness from 100 feet to 400 feet throughout the study area. Figure 4 depicts the variations in sand thickness across the study area. The log signatures in well 511 and well 714 have coarsening up signatures indicative of wave activity in a shallow water environment.

Figure 4. An isopach map of the Phacoides member with inset well logs to depict the changes in log signatures across the study area (modified from Weddle, 1965). The dashed circle indicates the location of the well type log shown in figure 5.

In the southeastern portion of the field, thin shale beds were identified within the Phacoides

sandstone causing stratigraphic compartmentalization of the reservoir into at least two

different units; the Upper and Main Phacoides. The upper Phacoides deposition is limited to

the eastern portion of the field. Completion reports show perforations in both the upper

Phacoides and Main Phacoides zones in this area of the field suggesting a possible lack of fluid

communication between the units (Fig 5).

Figure 5. Type log for the Phacoides in Well 562 depicting the Upper and Main units.

Production history

Oil was first discovered in the Temblor Formation in 1927 with the drilling of “Elliott” 1 in the

Kettleman North Dome field. The well blew out for three years before control of the flow could be established (Sullivan, 1966).

The McKittrick oilfield is located 40 miles southwest of Bakersfield (figure 1) and was discovered in 1896. It initially produced from several shallow zones. Surface seeps were the first indications that oil existed in the area, leading to the surface mining of heavy oil deposits in the early 1900’s (Taff, 1933). The trapping structure for the area is a closed, faulted anticline trending northwest-southeast parallel to the Temblor Range (Fig 6) (Weddle, 1965). There is over 900 feet of closure on the structure.

The Figure structure

structure is a northwest -

contour trending

map

displaying anticline

the cut

top by

of north

the

to Phacoides northeast -

sandstone trending

at faults

contour

(Weddle,

interval

1965).

100

ft.

The first producing well in the study area from the Temblor formation was “Spreckles” 555 completed in July 1964. This well was a dual-completion in both the Carneros and Phacoides sandstones with a combined initial production of 1097 bbls of clean oil with 0.1% water cut and

525 MCF of gas per day (Weddle, 1965). Pressure maintenance was assisted by water injection

from 1965-1974 along with gas injection from 1971-1975. As production slowed, pressure

maintenance efforts ceased. Analysis of producing wells in the field indicates that the

Phacoides member produced approximately five times as much as the Carneros member. As a result, this study focuses on the Phacoides member.

Methods

This project utilized IHS Petratm software for well log analysis and well correlation and Petrel

geological modeling software for mapping, cross sections, volumetric analysis, and structural

analysis. Well records and production histories are available from the California Division of Oil,

Gas and Geothermal Resources (DOGGR) and consist of scanned images of electric logs

(Resistivity/SP) and production and completion histories. Structure maps of the Phacoides zone

were created to examine the changes in sub-sea elevation of the reservoirs and the offset by

faulting. Cross sections were subsequently created to depict the vertical extent of the faults

and the lateral extent of the reservoir sands. Due to lack of available dip meter data, isochore

maps were created in true vertical thickness (TVT) rather than true stratigraphic thickness (TST).

The fault zones were modeled to better understand their vertical extent in the Phacoides using a structure map from the top of the Carneros to estimate the dip angles of the faults.

For EOR recovery estimation, original oil in place (OOIP) was calculated by creating a structure map of the top of the Phacoides sandstone and porosity and net/gross thickness maps in Petrel.

The imported tops from Petra were used in Petrel software to create the structure maps and calculate the volume of the reservoir above the oil water contact. A net/gross map (percentage of sand) and porosity map were created using well log data and technical reports for field wide values (CA DOGGR, 1998). Only areas containing hydrocarbons were used in the calculations.

Limited porosity log data were available so gas/oil and oil/water contacts were estimated using the cross section from Weddle (1965).

Equation (1) was used to calculate OOIP. Estimation of recoverable hydrocarbons was calculated by multiplying the OOIP by a recovery factor of 10-20% as shown in equation (2).

OOIP = (A * T * N/G * Φ * (1- Swirr)) /5.6146 (1)

OOIP = original oil in place

A = area of the zone (ft2)

N/G = net sand thickness divided by the gross interval thickness (decimal)

T = gross interval (ft)

Φ = average porosity (decimal)

1-Swirr = gross pore space minus the irreducible water saturation (decimal)

5.6146 = convert cubic feet to barrels (ft3 / bbl)

Additional recovery using CO2 injection was calculated using formula (2).

ER = OOIP * R (2)

ER = expected recovery of additional OOIP using CO2 injection

OOIP = original oil in place (bbls)

R = recovery rate (10 to 20 percent recovery is estimated from a typical CO2 EOR project)

(Enick and Olsen, 2012)

Production data was collected and analyzed to determine the cumulative produced from and injected fluid volumes into the reservoir annually on a well-by-well basis. The cumulative fluids produced are equivalent to the amount of pore volume available for CO2 storage, assuming that pore space compaction and water influx from the surrounding aquifer are negligible. The well production data collected ranged from 1964 to 2013. The production records after January

1977 are readily available on the DOGGR website in a tabular format. All production totals prior to 1977 were not available in digital format and were calculated from scanned monthly production reports and manually compiled into an excel spreadsheet. This task was completed for the 64 wells in the study area. The total production for oil, water, and gas were compared to annual field-wide production reports to verify accuracy and completeness.

Oil cumulative production totals are recorded in barrels at surface temperatures and pressures.

A reduction in volume occurs when gas comes out of solution in the oil as pressures and temperatures are reduced to surface conditions. In order to account for this reduction we must convert the cumulative volumes at surface conditions to reservoir conditions. The fraction at which oil volume is reduced is reported as the formation volume factor. CA DOGGR (1998) reported the field wide formation volume factor (BO) to be 1.5 (reservoir bbl/stock tank bbl = unitless). The formation volume factor is a dynamic value and changes as the field is produced.

However, without historical values, a constant value of 1.5 was assumed for BO. Volume adjustments are not required for the produced water because water is relatively incompressible and with increased pressure and temperature water undergoes minimal volumetric changes; therefore, one reservoir barrel of water is assumed equivalent to one barrel of water at the surface.

The produced and injected gas amounts were not included in the volumetric calculations because, in the absence of a significant gas cap, the majority of the gas produced from the reservoir is considered to be associated gas created by dissolution from the oil. As oil is

20 exposed to surface temperatures and pressures the liquid hydrocarbons shrink as gas comes out of solution in the oil. Based on volumetric calculations using the oil/gas contacts depicted in Weddle’s (1965) cross sections, the total volume of the original gas cap was less than 1% of the total volume of the reservoir.

In addition, the initial reservoir pressure and bubble point pressure were equal at 3550 psi as reported by the CA DOGGR annual report (1998). The bubble point pressure is the pressure at which gas starts to come out of solution in the oil. With continued production the reservoir pressure will decrease to the bubble point pressure and, if there is significant vertical permeability, a gas cap will start to form. If the reservoir pressure is at or above the bubble point, a free gas phase will not exist in the reservoir.

Total produced fluids were calculated using formula (3):

V= (Po*Bo) + (Pw – Iw)*Bw (3)

V = total volume of produced fluids at reservoir temperature and pressure (reservoir bbl)

Po = volume of oil produced at the well head (stock tank barrel)

Bo = oil formation volume factor (reservoir bbl/stock tank bbl = unitless) (Table 1)

Pw = volume of produced water with oil production (bbl)

Bw = water formation volume factor (the value of 1 was used)

Iw = volume of injected water (bbl)

Formula (4) was used to convert total produced fluids in reservoir barrels to the equivalent CO2 amount at reservoir conditions in metric tons:

3 3 1 metric ton = 1 BOE/6.29 (bbl/m ) * 500 Kg/m (density of CO2 in the reservoir) * .001 metric ton/Kg (4)

Analysis of the reservoir’s pressure response to production was conducted over the life of the field as fluids were removed and injected. This can be used as a reverse analog to how the reservoir pressure may respond to CCS injection and storage. In order to store CO2 safely and without compromising the integrity of the sealing layers, we endeavor to keep the reservoir pressure at or below the initial pressure of 3550 psi. Well histories that contain drill stem test

(DST) information were used to determine the reservoir pressures over time. The final shut-in

(FSI) values (PM) were obtained and tabulated for 41 DST tests in the field.

Recent reservoir pressures could not be obtained in the same manner because DST tests are conducted in the early stages of development as wells are being drilled. Because the reservoir is very mature and drilling is not occurring in the area, data from new wells are not available.

However, pressures can be estimated using static fluid levels in idle wells by measuring the height of the fluid column in the well bore above the perforated interval. By multiplying the height of the column of fluid over the top of the perforated interval by the hydrostatic pressure gradient, a pressure value (PM) can be estimated for the zone in the well that is open for production. The hydrostatic pressure gradient used for the formation water in this study is

0.45 psi/ft. Due to variances in formation depth, all pressures were converted to fractional hydrostatic values using equation (5). Normal hydrostatic pressure (PH) is determined by multiplying the total depth of the well bore from the surface to the highest perforation by the hydrostatic pressure gradient.

HF = (PM / PH) (5)

HF = Fractional hydrostatic pressure

PM = Pressure calculated by idle well fluid level

PH = Normal Hydrostatic pressure

This analysis may also indicate if an active water drive exists and whether the fault blocks are in communication with one another. The reservoir pressure should decrease with production unless the pore space is being re-filled by an active water drive. A rapid decrease in pressure with production suggests that a water drive is weak or absent. If an active water drive exists, water production will increase early in the life of the field and water will fill the pore space vacated by production, keeping the pressure high. Therefore, the amount of CO2 that can be stored and/or the rate at which it can be injected will decrease. Pressure variances between fault bounded areas of the field may provide evidence of hydraulic communication (or the lack thereof) between fault blocks within the reservoir.

Results

Volumetric analysis:

Volumetric analysis of the reservoir model (figure 7) revealed an OOIP of 119 MMBbls, which is similar to the 117 MMBbls reported by the National Energy Technology Laboratory NPC

(National Petroleum Council) Public Database (NETL 1984). By using a recovery factor of 15%, this would equate to an additional 17.8 MMBbls of recoverable oil by applying CO2 EOR. The

gas zone volume is 15,000 MCF. The fluid cutoffs and fault placement were estimated using a cross section from Weddle 1965 (figure 8).

Figure 7. Geological model used for volumetric calculations of original oil in place (OOIP). The colored planar features depict faults in the study area.

Reservoir continuity

Several analyses support compartmentalization of the reservoir: structural mapping, fluid level

variations, production history, and pressure analysis. The structural model of the field indicates

multiple north-south trending faults dividing the reservoir (figures 7 and 8). These faults

appear to be continuous throughout the study area with some minor east -west faults creating

offset between the major faults.

W E

A B

C D E F

Figure 8. A west to east cross section depicting the compartmentalization of the reservoir from faulting. The oil bearing portion of the Temblor formation is highlighted in green and the gas bearing is highlighted in pink (modified from Weddle 1965). Inset map is a structure map of the top of the Phacoides member with the cross section line in red (modified from Weddle 1965). The ABCDE and F labels indicate individual fault blocks.

The faults in the study area have compartmentalized the Phacoides reservoir into at least six

separate fault blocks labeled A, B, C, D, E and F (figure 9). The structurally highest

25 compartment, D, is separated by reverse faults in the eastern portion of the field and accumulated significant volumes of hydrocarbons.

Figure 9: The map shows the approximate location of the wells and the six separate fault blocks each shaded in different colors. Blocks A and B are presumed to be hydraulically connected as the fluid levels are the same in these blocks suggesting that the fault between them may be non-sealing.

In some of the faults (between blocks C and D, D and E, E and F), there is an offset of approximately 450 feet from the adjacent block, juxtaposing the Phacoides and the Cymric shale and possibly limiting communication across the fault (figure 8). The change in elevation of fluid contacts between the fault blocks also indicates the faults are sealing. Blocks A and B are considered hydrologically connected because, in these blocks, the fluid contacts are at the same elevation indicating leakage across the fault.

The reservoir has been compartmentalized by the faults into at least five different hydrological compartments. To sufficiently fill the reservoir with CO2, an injection well should be placed inside every sealing fault block. If the fault between blocks A and B is non-sealing, this would require a minimum of five injection sites throughout the study area.

Production analysis:

The net fluid produced from the Phacoides member is 71.5 MMRB. Using a density of 500

3 kg/m for CO2, this equates to 5.8 Million tons of CO2 that can be stored in the reservoir. Based

on the volumetric analysis performed in this study the Phacoides reservoir could store only 1.5

years of emissions from the La Palma power generation plant.

The cumulative production and equivalent amount of CO2 storage space within each fault block

is depicted in table 1. The A and B blocks were combined because they are known to be

hydrologically connected units and therefore considered as one reservoir. The ideal storage

site is in fault block A/B as it is the largest and most continuous reservoir and has produced the

most hydrocarbons. Fault block A/B is also well developed with the greatest number of wells

that can be converted to injection wells or monitor wells to examine the CO2 plumes for

migration pathways.

Net Fluid Produced C02 Equivalents Fault Block Number of Wells (MMRB) (millions of tons) A/B 28 40 3.2 C 3 5 0.4 D 8 13 1.0 E 6 5 0.4 F 19 9.5 0.8

Table 1. The cumulative production totals on a well-by-well basis for the individual blocks in

both reservoir barrels and tons of CO2.

Figure 10. This graph shows the production history by fluid stream for the Phacoides reservoir over the life of the field. The gas and injected gas totals are in MMCF versus the oil and water which are shown in MMRB.

The peak production year was in 1966 with over 5.3 MMBO. The production rate declined to less than half the peak value in five years. Gas injection commenced in 1966 to slow the decline of the reservoir pressure. In 1974, about 40% of the produced gas was being re-injected into the reservoir. Gas injection ceased in 1975 when oil production was surpassed by water production.

Water flooding was employed from 1970 – 1975 in an effort to increase production.

Waterflood operations only occurred within fault block F. The water produced tripled in fault block F during this time. An increase in water production was not observed in fault block E which may indicate the fault is sealing fluids. Only three wells were converted to injection wells for the water flood.

The low water production indicates that there is not a significant water drive. Strong water drives are usually indicated by a large increase in water production as oil production declines.

Compartmentalization of the reservoir can also be identified by examining production trends

across the study area. A well-by-well analysis of the net fluid production was mapped and

overlain on a net sand isopach map (figure 11). Clear divisions in production are observed

between some of the fault blocks as high production areas are in close proximity to areas with

low production. An example is well 47X-8 in block A and well 78X-8 in block C. The two wells

have equal amounts of sand and are approximately at the same elevation in the structure. Well

78X-8 has almost three times the production as 47X-8, possibly indicating separate reservoirs.

47X-8

78X-8

Figure 11. A color-filled net sand isopach map overlain by a structure contour map of the Phacoides. The structure map contours are 100 foot intervals. Cumulative production for each well is shown by pie charts; water (blue), oil (green), and gas (pink). The sizes of the pie charts represent the total amount of production. The greatest production occurs on the north flank of the main structure where the sands are thickest instead of at the crest of the anticline.

Reservoir Pressure Analysis:

The DST pressures (shown as fractional hydrostatic in Figure 12) were highly variable with an

average value of 0.81 and a standard deviation of 0.28 throughout the initial years of production. The relatively high standard deviation suggests the reservoir may be compartmentalized and the separate fault blocks are acting as independent reservoirs. The fractional hydrostatic pressures were graphed to examine changes in the reservoir pressure over time (Figure 12b). DST measurements were recorded from the years 1964 to 1967 and all later hydrostatic measurements were calculated using idle well fluid levels. There is a large gap in the data points for the reservoir pressures between the years 1968 to 1989 because no DST data or idle well fluid levels were collected over this time period.

The lowest average idle well pressure was observed in 1989 at 0.55 (55% of expected hydrostatic) and pressures appear to increase until the year 2002 (Figure 12b). This suggests the possibility of a weak water drive re-pressuring the reservoir. However, the pressure observation in 2002 may be an anomaly because only two idle well levels were recorded in that year giving an average fractional hydrostatic value of 0.89. In the years following 2002, the pressures appear to remain at around 60% of the expected hydrostatic.

)

Figure 12. a) Bar graph shows the fractional hydrostatic pressures for each DST and idle well fluid level measurement over time. b) Graph compares the fractional hydrostatic pressure of the reservoir from DST data (blue dots) and idle well fluid levels (red dots). The idle well fluid level values represent an average value for all fluid levels measured in a single year. The individual values are shown in 12a.

A spatial analysis was conducted using ArcGIS to map the pressure changes across the study area. This analysis provided more insight into the possibility of compartmentalization as spatial

pressure variations can be more easily identified. Since hydrostatic pressure measurements were limited, pressures over ten year spans were grouped together and examined to provide a

time lapse picture of pressure changes in the reservoir (figure 13).

33 periods pressure pressure Figure ) )

13. in

map map which Comparison

from from

pressures

1990 1964

– –

fractional

2000. 1967 were

with measured d)

Hydrostatic hydrostatic active and

gas

are

in pressure pressure jection not i ncluded

wells. changes map

from b) on ) )

from Hydrostatic

maps. 2000

1960 –

2006.

to pressure

present Water

map over injection

from ten

year

wells 1980

spans.

were –

1990.

not

Hydrostatic

active Hydrostatic

during

The hydrostatic pressures in the 1960’s indicate the reservoir pressures during the initial drilling

and production phase of the field (Fig. 13a). There are abrupt pressure changes across some of the fault blocks indicating separate reservoirs. Blocks C and D in particular appear to have varying pressures across the fault boundaries.

Active gas and water floods can increase pressures in the vicinity of the injection wells. The active gas injection wells during 1964 – 1967 are displayed on figure 13a along with pressures to determine any residual effect on the recorded reservoir pressures. The injection wells did have some effect in block A as reservoir pressures are close to initial hydrostatic conditions in the vicinity of the injection sites. Water injection began in 1970 and was not included on the pressure maps since they would not have any effect on the pressures collected in the 1960’s.

All injection ceased prior to the collection of idle well fluid level measurements and injection wells are not included on the maps from 1980-2006.

Through the 1980’s the pressure decreases dramatically, resulting in pressures below 50% hydrostatic along the main crest of the anticline (Fig. 13b). Throughout the 1990’s, production of the field slows and some pressures are observed to be increasing, particularly in the uplifted fault blocks (fault blocks C, D, and E). By the 2000’s reservoir pressures were elevated to as much as 92% of hydrostatic pressure around the outer edges of the field suggesting a weak water drive may be active along the edges of the field (figure 13d).

These pressure analyses can be used as a reverse analog to estimate the effect injection of CO2

will have on reservoir pressure. Pressure response of the reservoir to production can be defined by dividing the total amount of fluid production over time by the net pressure change of the reservoir. In this case the reservoir pressure decreased 1246 psi after removing a net fluid volume of 71.5 MMRB (or 57,000 reservoir bbls/psi). By reverse analogy, 57 MRB of injected fluid (which is equivalent to 4500 tons of CO2) would increase the reservoir pressure by

one psi. This is a maximum estimate as evidence indicates a slight water drive may be filling the flanks of the structure and occupying vacated pore space. In order to prevent overpressure and the possibility of fracturing the seal rock, the reservoir pressure should not exceed the initial reservoir pressure of 3550 psi.

Conclusion/Discussion:

The net fluid produced from the field was 71.5 million reservoir barrels (MMRB) which equates

to a total of 5.8 million tons of CO2 that can be stored in the reservoir. By using a recovery

factor of 15% additional recovery of OOIP there is also the potential to recover an additional

17.1 MMBL of oil through CO2 EOR which can help offset costs. The study area at McKittrick is

located within two miles of the La Palma power plant which produces over 4.5 million tons of

CO2 annually (WESTCARB, 2014). If equipped to capture CO2 the reservoir could store 1.5 years

of CO2 production from the La Palma power plant. The reservoir may be able to contain

additional CO2 as water is displaced in the reservoir. However, if the injection volume exceeds

36 produced volume there is a chance the increased reservoir pressure could fracture the seal rock allowing for leakage of CO2 through the seal or along the faults in the reservoir. However, a detailed cap rock integrity study would provide further insights on this issue.

The McKittrick oil field is located in a tectonically complex area which creates challenges for initiating an effective CCS program. Faulting has caused compartmentalization of the reservoir as evident from structural cross sections showing significant offset between fault blocks with varying fluid contacts and a high variability of reservoir pressures through time. This requires injection wells within each sealed fault block and can result in additional costs for implementing a CCS project. Currently the reservoir would require a minimum of five injection wells, one placed in every sealing fault block, but additional compartmentalization may be present. The injection of CO2 must be carefully monitored to determine that the volume injected into each individual fault block does not exceed the volume produced from that fault block. There is also a potential risk of leakage of CO2 as at least one of the faults appears to be non-sealing and may cause leakage in the reservoir. The pressure analysis revealed the presence of a slight water drive which may be filling the vacant pore spaces and reducing the total amount of storage space.

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APPENDICES Appendix A

Appendix A contains the fluid production tables that were produced during this thesis work. The fluid production data was collected from monthly production reports and an annually cumulative production total was calculated for all wells producing from the Phacoides.

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 48 31 224 945 248 213 867 375 410 795 922 476 9573 2480 2416 7642 5301 2934 1789 4599 5325 8011 5373 1569 1983 2295 1445 2377 1310 1157 2899 12214 16748 32816 17944 11314 12158 26047 203,290.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16 37 980 779 750 465 585 266 532 1304 3373 1002 1930 7091 9116 1346 2781 1512 1668 2441 3236 5960 5417 1058 1982 2040 4950 1430 7623 5412 1393 1134 8639 17553 12363 10445 12585 17302 14121 13293 24111 208,039.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 923 757 802 806 591 735 992 706 565 425 597 816 1295 1752 5769 1272 2827 1390 7356 1147 1506 1785 3858 6953 4757 1919 1981 5549 1823 7613 9232 1077 1106 4429 2844 12299 11992 13640 14061 23800 15322 16661 27551 221,300.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 784 936 756 932 955 425 437 573 3384 2570 3493 8422 3855 1740 1120 3874 1520 3390 5153 8245 1538 6439 1046 3492 4140 1980 3655 1513 8044 1374 2342 7862 3142 13454 10379 22469 12795 40388 20005 14719 16846 32103 280,309.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 623 670 594 949 727 924 603 841 9330 2452 3494 1049 9138 1435 2388 4020 1976 5402 4575 6847 1979 9087 6271 1258 1460 6405 1432 2921 8352 4834 15764 14664 19792 29165 31741 34838 28736 13435 17616 18807 27393 352,008.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 78 613 636 952 910 352 988 482 676 671 4280 1295 2761 4996 3840 2544 6701 9594 4422 1978 8593 1313 1082 8012 2837 5881 1013 8541 19150 24313 18973 11619 23951 22085 17385 15261 15563 18679 10253 13403 16081 17099 327,888.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 504 154 358 668 326 523 359 513 4434 2240 2782 9091 8294 2185 2444 2523 9465 6261 1199 1977 1527 1302 1580 6974 1755 3995 7519 1133 9830 25407 11274 16787 16860 13083 17883 26135 23310 13436 16390 10768 19766 11853 20329 19887 23778 376,884.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 353 306 785 621 319 8809 4620 4232 1840 4624 7625 6222 9996 2702 5027 9556 1759 5722 2002 1976 1755 1635 2620 1819 5289 8966 7453 43352 13843 22123 31934 20355 30816 30821 16119 11638 27104 14623 22137 22593 25070 439,185.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 61 490 191 749 804 303 3617 2295 4641 3296 5631 2409 1884 6059 1975 1728 1296 1701 2463 6767 6738 8282 17428 54355 20791 19355 31102 13811 24463 15947 39538 43405 34238 30181 11772 16365 11868 30620 12642 28373 24766 24036 16936 583,397.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 797 174 509 9815 3531 3639 4602 9569 9712 2995 2544 1927 1974 2529 2078 1701 8876 9542 7146 8598 2759 6850 9030 6317 35432 70224 66804 28664 11655 48491 27095 19067 56410 55039 40593 38276 12505 15175 26740 17099 34967 15076 34662 19009 32662 820,885.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16 152 132 450 8506 7090 4093 5744 1334 4358 4000 7830 7095 1973 1842 3704 2875 1750 7759 42577 88765 25914 90153 56368 45228 15485 11528 13358 79810 52009 57470 49089 43777 11586 17432 13048 20745 13230 32524 14645 33810 14855 17342 20041 21599 971,118.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 196 505 3858 1481 4880 1129 8889 5466 1209 5420 1972 5287 6982 5757 1456 5956 57979 52031 43864 18823 72369 33216 13221 45367 33763 12310 20710 68504 69001 28840 12482 35764 15241 16382 46974 12464 25666 33606 27812 11935 31992 29965 56438 25487 17933 102032 105881 142653 1,379,176.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 61 179 746 931 2423 7777 7490 7109 9674 8217 1971 9933 7301 1792 81301 86681 58291 38351 19349 60458 51669 56684 18651 28272 44944 10351 18055 45923 52715 26684 24302 74999 11055 17076 36693 33973 22313 26976 16159 33389 57536 59501 36287 24992 139226 128763 108115 125843 186615 112236 142498 2,180,559.00

Cummulative OilCummulative Production Well by (Rbbl) 0 0 0 0 0 0 0 0 0 0 0 0 0 58 85 844 1970 6915 2123 1839 3240 2221 64878 52833 57717 11866 45497 95521 28328 19842 43072 10237 69759 76979 17576 28137 30991 12174 84493 44308 10771 31223 90361 17962 36985 43052 44901 38376 51016 15468 22209 54171 71012 67035 58720 52660 120283 132430 370684 175304 127132 113547 139336 277386 203616 162958 3,340,131.00

0 0 0 0 0 0 0 0 0 0 0 376 348 1969 9705 5813 6597 5386 3901 1788 89666 20915 64831 47303 13951 40205 30754 52145 89820 93830 76357 22524 45032 50558 15819 20671 65973 14638 42802 45727 48523 15269 71955 91318 67240 91386 27295 27071 88533 88089 75828 91820 69047 158706 129460 328865 152085 105087 110887 121547 106998 268014 269463 104386 129720 120411 3,936,438.00

0 0 0 0 0 0 0 0 0 1968 7311 3669 7762 6554 4140 1555 79217 97244 23183 33971 16252 49592 17431 50133 17636 74855 12809 22504 21486 81558 92500 10247 21931 84611 95492 35307 47908 43181 28042 78146 70527 70574 89752 20163 69214 49102 84150 177139 105447 259292 194725 152426 133602 203956 151621 104227 172891 103761 233271 182558 123305 121551 104505 130675 107673 177970 4,560,304.00

0 0 0 0 0 0 0 0 0 0 0 0 0 1967 2804 5439 22232 14294 32234 28501 51995 27035 96008 26847 66801 18184 37323 29640 10508 31191 44753 29666 22905 83559 41182 46753 13624 30037 26294 65263 83964 111588 184378 193324 134196 153661 129878 156854 186605 236827 193572 179985 211019 108004 115946 108457 179355 207667 118499 172910 193554 185492 143801 185275 131640 111158 5,022,681.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1966 2425 1303 46492 23546 36906 59888 25618 17450 87412 27515 55452 90812 55963 11462 33210 22535 53765 201177 192712 103604 194222 187051 191496 189957 228005 236089 231278 275568 212989 106898 106373 139837 100962 140388 205581 143269 185605 100866 158045 220467 218618 222491 163643 5,308,945.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 255 2406 1690 6484 1965 8595 62593 25314 22829 39631 78680 20969 30861 69045 60848 28200 18646 83281 56095 23259 52775 58034 87190 88937 76415 240971 121195 103087 192205 150462 142550 142368 254246 112962 153310 332254 254805 138448 3,341,895.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1964 9785 1570 3242 38090 17598 70,285.00

UWI Totals 2901001 2901003 2901312 2901445 2902336 2903713 2905234 2905235 2905236 2905237 2905238 2905239 2905240 2905241 2905260 2905271 2905272 2905273 2905274 2905275 2905277 2905278 2905289 2905290 2905291 2905293 2905294 2905295 2905296 2905297 2905298 2905307 2905309 2905802 2923870 2923871 2923872 2923873 2923874 2923875 2923876 2923877 2923878 2923879 2923880 2923881 2923882 2941171 2941251 2941368 2941374 2941389 2941454 2941475 2941612 2941622 2941627 2941653 2941734 2941825 2943246 2943512 2946913 3025370 3025371

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 51 331 2006 1719 9425 5991 4888 9512 1329 9308 1417 3200 4963 6518 18742 11714 15684 12908 25433 143,133.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 58 56 197 2005 2575 4108 3287 2231 5520 6986 2711 6185 6392 14864 28981 11912 13445 13952 13898 40194 177,552.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 62 2004 1710 6466 6470 3285 7359 13792 34755 18703 22667 10153 19921 60675 10436 216,454.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2003 2927 6159 5608 4436 3566 14768 29472 14942 34013 13562 16440 30444 10404 186,741.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 446 283 2002 4620 6120 1167 5586 7142 5083 10451 26194 17193 31166 17360 15941 10684 159,436.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 56 248 2001 5845 5886 8004 1891 4261 16614 32585 13917 22603 19438 13625 10389 155,362.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 45 459 2000 5247 5664 3142 2133 8614 2020 14835 28342 10998 12389 13681 17171 124,740.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 1999 5660 4506 6179 5178 6613 17451 21654 19633 17825 17672 122,382.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1998 6561 4880 7083 4442 1154 20730 23319 22399 18424 10724 119,716.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 439 1997 7515 7618 4264 3473 13198 19995 22614 79,116.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1996 2613 5527 4659 6971 14017 16586 23381 19127 42021 134,902.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 297 454 1995 2424 9291 5758 1116 1553 22047 12178 21935 38359 115,412.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 800 1994 3275 5658 1100 5843 41073 15132 17864 10395 10099 29819 141,058.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1993 2037 2973 7864 40300 20084 10833 12844 26698 123,633.00

Cummulative OilCummulative Production Well by (Rbbl) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1992 7174 10207 17703 10575 11076 24463 81,198.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 646 1755 1991 8071 8053 11073 11624 33596 74,818.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 824 6747 1990 7219 2280 7696 15678 12459 11727 33087 97,717.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 81 49 63 641 342 5471 4005 3745 1989 1166 1078 1190 16273 14963 12729 11169 72,965.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 18 920 583 182 784 762 8343 4672 2831 1988 2353 2685 7180 4887 5897 3467 19953 10984 11743 10611 98,855.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 955 544 753 907 5598 3519 1987 3875 2759 6013 5352 6187 8791 1051 2097 2214 3743 2106 15685 11084 14984 17330 12754 128,301.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 69 27 38 156 882 522 986 8590 4330 8116 1986 4784 4484 3524 2528 5262 7440 7033 8389 8487 1105 29224 11629 10214 28758 13866 170,443.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 49 21 400 572 151 173 115 158 458 335 682 610 3387 8599 1080 2628 2575 1985 1316 1974 1041 1868 3862 2790 10823 27224 10901 15662 13072 112,526.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 66 696 322 648 425 193 413 107 644 305 510 674 785 545 1984 1025 4662 1462 4728 7166 1331 9131 1775 1653 2563 5189 3690 10926 11644 20631 11883 13303 119,095.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 8 0 689 445 162 248 3103 1149 3695 9008 4993 2013 2039 3648 4775 15365 49,327.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 116 520 1509 1108 6557 2012 6308 3044 6116 5829 14088 17471 23838 86,504.00

0 0 0 0 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 72 811 214 883 468 6825 2011 6304 6794 2482 5348 9359 1215 5866 28327 28672 103,641.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 15 906 747 8677 2010 1876 8190 2393 2307 3101 3050 8861 5715 23350 18540 87,732.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 7 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 828 775 8810 2009 5455 4274 7139 8515 8575 3835 9602 7009 19056 15230 11981 111,091.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 408 388 1020 2008 4041 6400 3655 9463 8608 2085 2013 8102 9414 18678 17558 13005 11154 115,994.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cummulative OilCummulative Production Well by (Rbbl) 902 311 2007 2727 7768 1290 3568 9470 1034 7726 1869 2016 9681 7781 20344 12856 12617 101,960.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 0 985 729 352 934 775 276 991 296 9300 9582 3009 1984 1585 2998 2038 5986 1293 25184 10288 11283 27927 37760 15585 21078 10717 15248 20719 11891 10265 14315 12192 285,583.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 28 93 18 304 503 275 377 850 112 717 850 8742 5856 5610 1251 4294 8834 1983 4150 1614 3007 8365 2196 62400 15779 15602 28408 20523 31773 35586 20951 12851 10519 10542 12008 40894 185710 561,592.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 84 154 318 508 355 332 6393 7572 1258 1973 5334 1913 9680 2000 1982 4517 5941 7638 1363 1768 2268 7646 1924 6385 1904 15292 10368 12362 16120 47080 23368 23776 21363 24843 10796 12860 33650 12251 13556 36550 393,463.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 245 600 272 853 805 453 755 908 147 7767 1434 1419 1981 9675 7031 2711 9979 4350 4461 3391 8254 2707 23157 12819 12110 11613 11621 65930 17250 11112 24298 10181 19232 30324 20458 10592 11249 15434 15576 37951 11562 13721 28095 482,502.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 587 208 939 689 153 7707 1549 2072 1980 1038 9207 2435 7285 1353 3373 1853 3656 8566 5089 3556 1237 8745 2471 1226 22981 12063 26868 22008 32597 36812 12339 10473 12139 17803 23596 15054 19030 11862 13582 16255 137650 157189 675,295.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 471 749 440 605 425 418 540 422 390 9121 1979 3219 3363 1078 1853 9719 9364 5617 2615 8077 3044 1017 28075 35870 40427 32251 13190 31259 11574 15778 10046 11129 19328 28254 20344 37474 10985 16915 26387 195824 234640 882,297.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 64 444 755 722 491 682 667 216 596 761 752 532 9220 1471 1978 1991 3531 4585 1372 8835 6995 6852 3466 5992 2188 38476 27818 28509 38019 13232 31239 19641 11274 10640 23355 12817 18586 62517 13405 18364 28220 139178 228711 827,181.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 708 959 305 465 523 4653 1240 9602 3571 1283 1704 1977 2471 2964 4089 7773 4054 4021 3020 4668 1319 1303 5588 5866 7022 2097 32432 32892 10760 11212 22578 13052 28838 24149 13218 30637 17509 21833 23703 84297 13900 24414 36983 148072 262086 933,833.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 992 366 988 955 861 568 973 7691 1976 4697 3248 3387 6845 3876 9444 4070 3796 2143 1170 6231 6196 6141 4519 14071 27504 16803 10898 25808 19377 15267 34729 10609 50606 19135 70397 14744 34619 24295 192949 334130 995,098.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16 783 506 824 693 145 6784 4577 2908 1975 3195 2488 2790 2120 3817 1336 6233 5803 4437 1737 1074 5928 6270 6311 2013 1038 40255 15677 12208 49327 18538 20006 34206 11906 74593 17180 99080 10210 25543 20040 107138 280155 909,888.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 553 415 423 846 792 487 3613 2119 2095 1974 1504 1461 2766 3038 3940 3091 1270 3755 8570 1460 1035 1258 4696 1937 9238 6301 7026 2186 1100 44225 85538 48724 15217 59986 11850 99131 17933 13969 33091 17008 15509 18668 318951 876,785.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 64 589 751 979 668 411 114 545 2319 2141 1973 2544 1059 1635 2513 3342 2685 1209 3743 2576 4624 1900 1117 1970 5177 3524 9750 5832 9199 6460 1116 1083 11103 90599 39013 40789 15275 82211 18502 27437 11666 43427 21512 15668 424951 923,792.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 24 87 418 592 510 593 292 671 591 715 806 928 143 502 512 332 2540 2339 2224 1972 1204 3719 1614 2611 2154 1628 1507 2993 2153 6423 2706 2671 9726 3384 12037 12494 16543 61664 15869 12793 31455 25486 58737 17199 10746 24940 146305 277820 783,400.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 19 40 995 511 962 980 794 510 597 164 2402 1487 6026 1971 1582 2338 1314 6401 2622 2682 3749 1148 3163 4158 5057 1704 2266 1788 4053 1065 8632 2873 1353 2299 89644 18341 13800 28903 15911 11562 11884 29795 25872 27791 63307 18452 21308 14983 18340 233071 718,698.00 Cummulative Water ProductionCummulative Well by (Rbbl)

0 3 0 0 0 0 0 0 0 0 0 0 0 0 16 68 10 487 823 294 533 527 596 611 404 942 2382 6624 1970 3378 1672 1989 3362 5250 2008 1269 1982 1508 2591 2574 8529 2087 1238 2851 2450 1139 3159 1017 1630 1247 4433 47995 99756 28561 11667 10529 10274 23270 25080 31275 15975 30450 17854 22488 188754 108197 743,808.00

0 0 0 0 0 0 0 0 0 0 0 942 689 737 932 367 892 373 214 691 263 967 487 822 1969 1013 6044 8379 1068 1018 3734 3015 3874 1685 1046 1271 2639 1626 4133 6271 1417 2545 1086 2308 1945 2205 1886 1601 2487 1558 5002 15898 75315 24685 14524 23450 32999 56159 13575 33005 30485 18386 16205 93764 21304 103308 652,294.00

0 0 0 0 0 0 0 0 0 16 657 790 453 845 738 443 521 906 309 784 881 975 870 250 467 840 1968 1198 1573 1102 1545 1667 3002 3348 2189 4295 4643 1268 2507 2286 2712 1551 1817 3170 1405 1945 1914 1557 1542 3076 1572 67568 24274 12751 18067 17642 17438 11944 27885 57256 19367 14996 54170 26105 33184 130413 596,689.00

0 0 0 0 0 0 0 0 0 0 0 0 0 76 866 300 451 903 488 283 538 557 290 785 139 318 393 963 1967 3676 1073 2765 2842 1752 6984 1059 9810 1446 1225 7195 9552 4360 1005 1036 1168 6188 2904 3454 2399 4607 2721 1710 2128 4069 3772 6712 1403 21583 57096 31114 19186 18974 38308 79767 24244 21637 418,274.00

0 0 0 0 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 421 660 303 585 686 560 555 186 509 756 316 903 732 920 752 754 300 729 167 1966 1354 3592 1399 3965 3867 3348 9113 1782 1115 1183 1466 1280 1148 1383 1376 1516 1639 1038 4005 2016 79635 14299 160018 312,333.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 34 327 379 181 548 484 177 182 738 108 513 179 211 311 440 656 771 290 307 888 635 837 478 328 583 738 285 527 1965 2195 1437 6834 2328 5669 45901 27958 43210 10848

158,515.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 52 155 354 1964 2833 3,394.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 321 2006 2383 2555 7157 1413 1474 3930 38628 32927 13259 49946 11239 26269 16808 28404 30214 103035 107955 477,917.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 452 2005 3230 5887 2850 2250 1911 29432 88634 13615 89122 14399 25437 21439 47749 16427 24142 14069 16783 50442 468,270.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2004 5577 7597 2608 3921 7422 4509 2774 37502 94381 13743 19745 14308 19694 69430 107151 410,362.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 58 505 2003 1750 1595 8432 2656 36047 87491 86872 19651 14940 21088 61367 342,452.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 25 467 493 123 2002 1769 1641 2969 29539 87390 15120 99351 12365 14759 20191 57798 344,000.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 407 524 537 2001 1630 3664 9255 2777 20601 78229 65129 10969 19289 21690 92809 327,510.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 964 189 2000 9162 1772 3974 4892 2121 22062 53465 82034 11036 21995 20844 117628 352,138.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 46 404 9140 1999 3131 6061 3730 4937 27790 37974 83530 21867 198,610.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1998 2150 1458 3063 8330 6933 12527 47817 20848 57769 14543 175,438.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 223 363 418 6190 1997 3958 4977 11787 14182 42,098.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 435 578 8670 1996 5272 8753 1581 23336 27267 12534 88,426.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 181 9924 1995 4021 4737 3400 1496 5157 29502 30029 29753 15246 133,446.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 735 257 161 588 7855 1994 6067 4939 31573 53778 31702 11593 17203 166,451.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 841 921 903 1993 12733 33914 51683 15085 21021 137,101.00

Cummulative Water ProductionCummulative Well by (Rbbl) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 636 7895 1992 3022 2417 10537 19786 44,293.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 990 749 588 4943 1991 1364 49200 13341 71,175.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 340 478 563 2590 1990 1125 3187 12368 13067 25048 58,766.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 35 112 275 563 342 1989 1910 1321 2558 2239 7021 1292 7979 4720 13851 11771 55,989.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 744 652 309 1988 1556 2151 2476 6923 3727 1671 2289 8428 10576 21523 16184 16532 48670 10364 18300 173,075.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 519 781 698 534 212 483 151 1987 7625 1260 2536 7729 6667 6936 19478 18317 15509 21243 16120 33141 46574 13423 30101 250,037.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 74 84 307 605 884 323 824 1986 1432 6454 1841 2633 9935 4219 1971 9890 8007 1460 1910 1046 17666 23459 14780 20757 21189 11918 20339 13886 197,893.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 482 792 274 819 175 349 572 372 100 253 1985 8663 1289 6833 5043 7076 3170 2465 1495 3567 5740 6712 1441 1414 9254 6230 7274 23928 15863 121,645.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 56 1153 2013 1544 3900 9255 4884 7324 76693 37701 18633 39549 16209 29143 100961 347,005.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 613 2119 2012 1815 9600 53616 16866 49135 71088 21071 30217 15892 29855 106641 408,528.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 185 4523 2011 4212 7134 9004 9120 22710 10770 10336 48810 68485 15162 34677 89735 10410 26202 371,475.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 35 2010 1141 1451 5622 1908 8965 9770 32277 41636 81306 91358 34627 39601 20166 26040 395,903.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 70 67 505 2009 1241 9095 1064 2415 14994 94683 74955 23733 32559 59961 12548 31685 32694 392,269.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 20 834 2008 1147 4143 5239 3135 1027 7862 54122 34797 95281 82809 28327 34464 78860 11498 16898 33047 493,510.00

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 824 2007 7246 1516 2129 3484 2778 2390 56472 88761 18463 17904 23644 32454 12598 13365 31178 315,206.00

Cummulative Water Production by Well Production Cummulative (Rbbl) Water

APPENDICES Appendix B

Appendix B contains the hydrostatic pressure tables that were produced during this thesis work. The pressures data for the reservoir was collected from DST records in the well data files available from DOGGR. The idle well fluid levels collected were provided from the operator of the field.

Percent Hydrostatic Pressure Data Collected from DST API Well Name location Sec, T, R Test date Formation Top depth pressure % hydrostatic 2901003 Spreckles 511 16, 30S, 22E 12/21/1964 Phacoides 8086 3755 1.06 2901003 Spreckles 511 16, 30S, 22E 12/24/1964 Phacoides 8145 3773 1.05 2901312 Section 16Z #523 16, 30S, 22E 11/11/1966 Phacoides 8230 2997 0.83 2901312 Section 16Z #523 16, 30S, 22E 12/8/1966 Phacoides 9040 2930 0.74 2905234 Section 7Z #536 7, 30S, 22E 8/14/1965 Phacoides 8413 2905 0.78 2905234 Section 7Z #536 7, 30S, 22E 8/16/1965 Phacoides 8317 3419 0.93 2905234 Section 7Z #536 7, 30S, 22E 8/17/1965 Phacoides 8372 2876 0.78 2905236 Section 7Z #556 7, 30S, 22E 2/22/1965 Phacoides 8239 2200 0.61 2905236 Section 7 #556 7, 30S, 22E 5/22/1965 Phacoides 8239 2200 0.61 2905238 Section 7Z #565 7, 30S, 22E 9/18/1965 Phacoides 8172 3402 0.95 2905238 Section 7Z #565 7, 30S, 22E 10/6/1965 Phacoides 8276 3597 0.99 2905238 Section 7Z #565 7, 30S, 22E 10/8/1965 Phacoides 8276 3332 0.92 2905238 Section 7Z #565 7, 30S, 22E 10/9/1965 Phacoides 8246 3123 0.86 2905240 Section 7Z #587 7, 30S, 22E 3/21/1965 Phacoides 7820 3628 1.05 2905272 Spreckles #513 16, 30S, 22E 10/21/1964 Phacoides 8307 3300 0.90 2905272 Spreckles #513 16, 30S, 22E 10/22/1964 Phacoides 8403 3400 0.92 2905273 Spreckles #524 16, 30S, 22E 2/21/1965 Phacoides 8810 3724 0.96 2905290 Sec. 17Z #543 17, 30S, 22E 11/5/1965 Phacoides 7790 3245 0.95 2905291 Sec. 17Z #552 17, 30S, 22E 9/24/1965 Phacoides 7685 3586 1.06 2905291 Sec. 17Z #552 17, 30S, 22E 10/11/1965 Phacoides 8035 2815 0.80 2905293 Sec. 17Z #561R 17, 30S, 22E 4/15/1965 Phacoides 7780 3698 1.08 2905293 Sec. 17Z #561R 17, 30S, 22E 4/17/1965 Phacoides 7850 3628 1.05 2905293 Sec. 17Z #561R 17, 30S, 22E 5/1/1965 Phacoides 8005 2514 0.71 2905293 Sec. 17Z #561R 17, 30S, 22E 5/2/1965 Phacoides 8050 2712 0.77 2905296 Sec. 17Z #581 17, 30S, 22E 10/16/1965 Phacoides 7828 3506 1.02 2905297 Sec. 17Z #583 17, 30S, 22E 4/4/1965 Phacoides 7997 2278 0.65 2905309 Sec. 18Z #581 18, 30S, 22E 1/10/1965 Phacoides 7555 3434 1.03 Jacobson 18Z 2905309 #581 18, 30S, 22E 2/11/1965 Phacoides 7655 3308 0.98 2902336 Sec. 7 #554 7, 30S, 22E 11/18/1965 Phacoides 8213 3468 0.96 2905271 Sec. 16 #586 16, 30S, 22E 9/9/1967 Phacoides 9520 4803 1.15 2905274 Sec. 16 #526 16, 30S, 22E 10/28/1964 Phacoides 8740 1392 0.36 2905274 Sec. 16 #526 16, 30S, 22E 10/30/1964 Phacoides 8792 4877.5 1.26 2905287 Sec. 17 #512R 17, 30S, 22E 12/9/1965 Phacoides 7820 2400 0.70 2905294 Sec. 17 #572 17, 30S, 22E 6/18/1965 Phacoides 7610 3561 1.06 Main 2905298 Sec. 17 #585 17, 30S, 22E 12/14/1964 Phacoides 8005 904.5 0.26 2905298 Sec. 17 #585 17, 30S, 22E 12/15/1964 Phacoides 7930 2266.5 0.65 2905298 Sec. 17 #585 17, 30S, 22E 12/18/1964 Phacoides 8070 2371 0.67 2905802 Sec. 16 #534 16, 30S, 22E 8/17/1964 Phacoides 8750 1806 0.47 2905802 Sec. 16 #534 16, 30S, 22E 8/19/1964 Phacoides 8850 1300 0.33 2941171 Sec. 16 #573 16, 30S, 22E 3/16/1967 Top Phacoides 8870 3065 0.79

Idle Well levels and Hydrostatic Pressure Data Well API Name location Sec, T, R Test date Top Perf Fluid level calc press (.44psi/ft) % hydrostatic 02901001 567 7, 30S, 22E 10/30/1989 7880 3447 1950.52 0.56 02905238 565 7, 30S, 22E 10/30/1989 8170 5826 1031.36 0.29 02905290 543 17, 30S, 22E 10/30/1989 7623 1312 2776.84 0.83 02905291 552 17, 30S, 22E 10/30/1989 8005 7900 46.2 0.01 02905293 561R 17, 30S, 22E 10/30/1989 8145 3477 2053.92 0.57 02905295 573 17, 30S, 22E 10/30/1989 7705 397 3215.52 0.95 02905298 585 17, 30S, 22E 10/30/1989 8065 6527 676.72 0.19

02923872 38X-8 8, 30S, 22E 10/30/1989 7620 7442 78.32 0.02

02923876 67X-8 8, 30S, 22E 10/30/1989 8000 4240 1654.4 0.47 02923881 52X-18 18, 30S, 22E 10/30/1989 7900 4667 1422.52 0.41 02923882 61X-18 18, 30S, 22E 10/30/1989 7740 6222 667.92 0.20 02905235 538 7, 30S, 22E 10/31/1989 8090 3325 2096.6 0.59 02905293 561R 17, 30S, 22E 10/31/1989 8145 3477 2053.92 0.57 02923875 65X-8 8, 30S, 22E 10/31/1989 8300 5033 1437.48 0.39 02923880 41X-18 18, 30S, 22E 10/31/1989 8690 5734 1300.64 0.34 02941627 531 16, 30S, 22E 11/1/1989 8915 3569 2352.24 0.60 02946913 521 16, 30S, 22E 11/1/1989 8492 4040 1958.88 0.52 02941374 575 16, 30S, 22E 11/4/1989 9239 5277 1743.28 0.43 02901003 511 16, 30S, 22E 11/5/1989 8090 3538 2002.88 0.56 02901445 543R 16, 30S, 22E 11/5/1989 9040 2745 2769.8 0.70 02905272 513 16, 30S, 22E 11/5/1989 8305 1678 2915.88 0.80 02941171 573 16, 30S, 22E 11/5/1989 9000 3081 2604.36 0.66 02941389 562 16, 30S, 22E 11/5/1989 9015 183 3886.08 0.98 02901445 543R 16, 30S, 22E 11/30/1989 9040 2745 2769.8 0.70 02905260 518 9, 30S, 22E 11/30/1989 8230 5612 1151.92 0.32 02941622 577 9, 30S, 22E 11/30/1989 9837 854 3952.52 0.91 02946913 521 16, 30S, 22E 11/30/1989 8492 4040 1958.88 0.52 02901003 511 16, 30S, 22E 6/22/1993 8090 798 3208.48 0.90 02901312 523 16, 30S, 22E 6/22/1993 8220 5243 1309.88 0.36 02941171 573 16, 30S, 22E 6/22/1993 9000 2573 2827.88 0.71 02941374 575 16, 30S, 22E 6/22/1993 9239 4291 2177.12 0.54 02941612 553 16, 30S, 22E 6/22/1993 8910 1736 3156.56 0.81 02943246 585 16, 30S, 22E 6/22/1993 9345 10 4107.4 1.00 02943512 566 16, 30S, 22E 6/22/1993 9260 576 3820.96 0.94 02905234 536 7, 30S, 22E 6/25/1993 8230 1988 2746.48 0.76 02905235 538 7, 30S, 22E 6/25/1993 8090 3975 1810.6 0.51 02905239 576 7, 30S, 22E 6/25/1993 8000 5352 1165.12 0.33 02923875 65X-8 8, 30S, 22E 6/26/1993 8300 7105 525.8 0.14

02901001 567 7, 30S, 22E 8/1/1994 7880 1462 2823.92 0.81 02905238 565 7, 30S, 22E 8/1/1994 8170 2644 2431.44 0.68 02905260 518 9, 30S, 22E 8/1/1994 8230 5165 1348.6 0.37 02905290 543 17, 30S, 22E 8/1/1994 7623 1446 2717.88 0.81 02905291 552 17, 30S, 22E 8/1/1994 8005 7324 299.64 0.09 02905295 573 17, 30S, 22E 8/1/1994 7705 2301 2377.76 0.70 02905298 585 17, 30S, 22E 8/1/1994 8065 4758 1455.08 0.41 02923876 67X-8 8, 30S, 22E 8/1/1994 8000 6438 687.28 0.20 02923881 52X-18 18, 30S, 22E 8/1/1994 7900 1337 2887.72 0.83 02923882 61X-18 18, 30S, 22E 8/1/1994 7740 6173 689.48 0.20 02941622 577 9, 30S, 22E 8/1/1994 9837 908 3928.76 0.91 02946913 521 16, 30S, 22E 8/1/1994 8492 4601 1712.04 0.46 02905307 572R 18, 30S, 22E 9/19/1995 7790 6840 418 0.12 02902336 554 7, 30S, 22E 9/25/1995 8160 3121 2217.16 0.62 02905271 586 16, 30S, 22E 9/27/1995 8850 3641 2291.96 0.59 02941454 542 16, 30S, 22E 9/27/1995 8816 4280 1995.84 0.51 02941475 568 9, 30S, 22E 9/27/1995 1236 78 509.52 0.94 02941389 562 16, 30S, 22E 10/6/1995 9015 4893 1813.68 0.46 02941612 553 16, 30S, 22E 8/21/1996 8910 7331 694.76 0.18 02905234 536 7, 30S, 22E 8/23/1996 8230 766 3284.16 0.91 02901312 523 16, 30S, 22E 8/24/1996 8220 4000 1856.8 0.51 02905236 556 7, 30S, 22E 8/24/1996 7970 636 3226.96 0.92 02923881 52X-18 18, 30S, 22E 8/24/1996 7900 176 3398.56 0.98 02943246 585 16, 30S, 22E 8/24/1996 9345 124 4057.24 0.99 02923875 65X-8 8, 30S, 22E 8/29/1996 8300 4500 1672 0.46 02905293 561R 17, 30S, 22E 9/4/1996 8145 3565 2015.2 0.56 02901003 511 16, 30S, 22E 6/25/1997 8090 5510 1135.2 0.32 02905234 536 7, 30S, 22E 6/25/1997 8230 1300 3049.2 0.84 02941171 573 16, 30S, 22E 6/25/1997 9000 5010 1755.6 0.44 02923880 41X-18 18, 30S, 22E 7/22/1997 8690 6620 910.8 0.24 02905272 513 16, 30S, 22E 7/23/1997 8305 2550 2532.2 0.69 02941374 575 16, 30S, 22E 7/23/1997 9239 4000 2305.16 0.57 02941612 553 16, 30S, 22E 9/24/1997 8910 3600 2336.4 0.60 02923873 47X-8 8, 30S, 22E 6/7/2000 7832 1116 2955.04 0.86 02941454 542 16, 30S, 22E 6/7/2000 8816 155 3810.84 0.98 02902336 554 7, 30S, 22E 6/14/2000 8160 930 3181.2 0.89 02905271 586 16, 30S, 22E 7/19/2000 8850 6450 1056 0.27 02905307 572R 18, 30S, 22E 1/17/2001 7790 1275 2866.6 0.84 02901001 567 7, 30S, 22E 1/23/2001 7880 53 3443.88 0.99 02905297 583 17, 30S, 22E 1/26/2001 8006 900 3126.64 0.89 02905272 513 16, 30S, 22E 6/12/2002 8305 1134 3155.24 0.86 02943246 585 16, 30S, 22E 6/12/2002 9345 850 3737.8 0.91 02901445 543R 16, 30S, 22E 5/5/2004 9040 937 3565.32 0.90

02905238 565 7, 30S, 22E 7/12/2004 8170 882 3206.72 0.89 02905290 543 17, 30S, 22E 7/12/2004 7623 1350 2760.12 0.82 02923876 67X-8 8, 30S, 22E 7/12/2004 8000 6500 660 0.19 02905260 518 9, 30S, 22E 7/13/2004 8230 5198 1334.08 0.37 02946913 521 16, 30S, 22E 7/13/2004 8492 1900 2900.48 0.78 02901003 511 16, 30S, 22E 9/3/2005 8090 567 3310.12 0.93 02902336 554 7, 30S, 22E 8/15/2006 8160 347 3437.72 0.96 02905271 586 16, 30S, 22E 8/15/2006 8850 1040 3436.4 0.88 02923873 47X-8 8, 30S, 22E 8/15/2006 7832 7088 327.36 0.09 02943512 566 16, 30S, 22E 8/15/2006 9260 95 4032.6 0.99 02905272 513 16, 30S, 22E 5/15/2007 8305 1922 2808.52 0.77 02905297 583 17, 30S, 22E 5/15/2007 8006 2615 2372.04 0.67 02941171 573 16, 30S, 22E 5/15/2007 9000 5859 1382.04 0.35 02941374 575 16, 30S, 22E 5/15/2007 9239 3875 2360.16 0.58 02946913 521 16, 30S, 22E 5/15/2007 8492 1827 2932.6 0.78 02941612 553 16, 30S, 22E 7/25/2007 8910 7434 649.44 0.17